​On February 28, 2023, in Docket No. ER18-99, FERC issued an order[1] addressing exceptions to an Initial Decision issued on December 6, 2021.[2]  The Initial Decision concerned disputes arising from Southwest Power Pool, Inc.’s (SPP) proposal to revise its Open Access Transmission Tariff (Tariff) to include the annual transmission revenue requirement (ATRR) of transmission facilities associated with the City of Nixa, Missouri (City of Nixa), owned by GridLiance High Plains LLC (GridLiance),[3] in one of SPP’s existing transmission pricing zones, SPP Pricing Zone 10 (Zone 10), for purposes of rate recovery (Nixa Assets).  In the Initial Decision, the Presiding Judge concluded that SPP’s proposal to incorporate the Nixa Assets in Zone 10 is consistent with cost causation principles and is otherwise just and reasonable.  In its Order on Initial Decision, FERC affirmed the Initial Decision.  On March 29, 2023, a joint request for rehearing was filed by two different intervener groups.  In its Order on Rehearing issued July 5, 2023, FERC modified the discussion in the Order on Initial Decision and continued to reach the same result.
 
Background:  SPP uses a zonal rate design, pursuant to which its footprint is separated into several transmission pricing zones for purposes of establishing transmission service rates.  The Tariff specifies a zonal ATRR for each pricing zone that is based on the sum of the ATRRs for each transmission owner in the zone.  The charges for Network Integration Transmission Service (network service) in a pricing zone are calculated by multiplying a customer’s percentage share of total load in the zone (i.e., its load ratio share) by the zonal ATRR.  When a new transmission owner is added to an existing pricing zone, the ATRR for its transmission facilities in the zone and any associated load not already included in the zonal load are added to the existing zone’s zonal ATRR and total load.  In 2017, SPP instituted a new Transmission Owner Zonal Placement Process (Zonal Placement Process) to review and determine zonal placement for existing transmission facilities that new SPP transmission-owning members propose to include under the SPP Tariff.  A group of SPP transmission owners challenged the SPP Zonal Placement Process, arguing that allocating the costs of a new SPP member’s transmission facilities to existing customers of a zone results in an unjust and unreasonable cost shift between new and existing transmission customers.[4]  Although FERC denied the complaint,[5] it also stated that parties may challenge the placement of a new transmission owner’s facilities in a transmission pricing zone.[6]  The Nixa Assets consist of approximately 10 miles of transmission lines and related facilities interconnected to Southwestern Power Administration (Southwestern) in Zone 10 and to City Utilities of Springfield, Missouri (City Utilities) in SPP Pricing Zone 3 (Zone 3).[7]  On October 18, 2017, SPP submitted proposed Tariff revisions to add an ATRR and a formula rate template and implementation protocols for the Nixa Assets.  SPP explained that it had used its Zonal Placement Process to place the facilities in Zone 10.  On March 15, 2018, FERC set the Tariff revisions for hearing and settlement judge procedures.[8]  After a settlement was unsuccessfully put forth to FERC, in late 2021, the Presiding Judge issued the Initial Decision, which addressed three general issues:  (1) whether, and to what extent, the placement of the Nixa Assets in Zone 10 involves a cost shift; (2) whether benefits accrue to Zone 10 customers as a result of placing the Nixa Assets in Zone 10; and (3) whether the benefits justify the cost shift.  The Presiding Judge determined that SPP’s proposal to incorporate the Nixa Assets in Zone 10 is consistent with cost causation principles and is otherwise just and reasonable.[9]  Specifically, the Presiding Judge found that:  (1) the placement of the Nixa Assets in Zone 10 will result in a $1.8 million cost shift to Zone 10 customers; (2) the Nixa Assets accrue substantial, specific, but unquantifiable benefits (i.e., integration benefits, reliability enhancements, and support for power transfers) to Zone 10 customers; and (3) those benefits justify the cost shift involved in the placement of the Nixa Assets in Zone 10.  In its Order on the Initial Decision, FERC affirmed the findings that SPP’s proposal to include the ATRR for the Nixa Assets in Zone 10 is just and reasonable and consistent with the cost causation principle and, accordingly, accepted SPP’s proposed Tariff revisions.  As to the amount of the cost shift, FERC determined that the Presiding Judge properly balanced competing evidence to reach the finding that the cost shift at issue in this proceeding should be calculated as GridLiance’s proposed ATRR for the Nixa Assets, which is $1.8 million.  In doing so, FERC rejected arguments that the proper amount of the cost shift should be measured by the amount or percentage of the Gridliance ATRR for the Nixa Assets  that will be paid by non-City of Nixa customers rather than the full amount of the GridLiance ATRR.  FERC explained that “the City of Nixa is already a Zone 10 customer and the Commission’s evaluation of the cost shift to Zone 10 customers can and should incorporate costs paid by the City of Nixa as well as other customers in that zone.”  FERC also affirmed the Presiding Judge’s finding that the Nixa Assets provide benefits that accrue to Zone 10 customers, concluding that the record supports the finding that the Nixa Assets provide integration, reliability, and power transfer benefits to Zone 10 customers.  Responding to “the main argument raised on exceptions” that the benefits that the Nixa Assets provide allegedly accrue mostly, if not entirely, to the City of Nixa rather than other Zone 10 customers, FERC found that the Presiding Judge properly evaluated the benefits of the Nixa Assets to all Zone 10 customers—including the City of Nixa—rather than restricting his findings to non-City of Nixa customers.  In doing so, FERC explained that “under SPP’s zonal rate design, all customers in a pricing zone pay a rate based on the ATRRs associated with all transmission facilities in that zone, regardless of which facilities may have previously been used to provide service to a specific customer prior to the customer or the Transmission Owner joining the [Regional Transmission Organization (RTO)].”  FERC  also affirmed the Presiding Judge’s finding that the benefits to Zone 10 customers from the Nixa Assets are roughly commensurate with their costs, and therefore SPP’s proposal to include the Nixa Assets in Zone 10 was just and reasonable.  FERC found that arguments that it should treat the “roughly commensurate” standard as requiring that any costs of a facility should be distributed “roughly proportionate” to the usage of that specific facility were “contrary to Commission precedent and inconsistent with how costs are allocated within SPP.”  Finally, FERC affirmed the Presiding Judge’s dismissal of the alternative rate proposals made by intervenors since, having affirmed the Presiding Judge’s finding that SPP’s proposal is just and reasonable, it “need not consider whether the proposal is more or less reasonable than other alternatives.”
 
Arguments on Rehearing:   Intervener arguments centered around their claim that a cost shift associated with a zonal placement decision under SPP’s Tariff cannot be just and reasonable unless each customer (or group of customers)  that will bear some portion of the costs of those assets (or group of assets) is deriving a benefit from those specific assets that is “roughly proportionate” to those costs.   The interveners sought to apply an asset-level, beneficiary-pays rough proportionality requirement.  FERC disagreed with this view as it  does not square with the existing zonal rate construct under the SPP Tariff.  Under that construction, a transmission customer taking network service shall pay a monthly demand charge for the SPP Pricing Zone where the load is located (Load Ratio Share).  As evident in this formula/calculation, SPP’s zonal rate construct does not attempt to measure each transmission customer’s benefit from each transmission asset included in the zonal ATRR.  Nor does it charge each customer transmission costs on an asset-by-asset basis.  Instead, under that zonal construct, the costs and benefits associated with network service in a zone are assessed on an aggregate level, with each customer paying for transmission service based on its load ratio share, which reflects its total use of the aggregate assets in the zone.   Even if a customer does not benefit from a particular transmission asset in a manner roughly commensurate with its load ratio share, this does not demonstrate that the customer is not overall receiving roughly commensurate benefits from the transmission assets within the zone as compared to the zonal rates it is paying under SPP’s Tariff.  The interveners also attempted to align their proposed proportionality requirement with SPP’s zonal rate construct by arguing that RTO zones will be ordinarily configured to allocate the costs of transmission facilities to the customers for whom they were constructed.   FERC agreed that, in a typical case, it expects that a transmission asset should be included in the same zone as the customers for whom they were constructed and continue to serve.   But this principle does not establish that zones generally, or SPP Pricing Zones in particular, have been or must be constructed to ensure that each customer benefits from each asset in the zone in rough proportion to the costs it pays for that specific asset, or that new assets that may be included in a zone must meet such a requirement.
 
FERC asserted that the facts of this case are as follows:  including the Nixa Assets in Zone 10 will result in a $1.8 million increase in the zonal ATRR, a portion of which will be borne by the City of Nixa based on its load ratio share under SPP’s existing Tariff.   Under these circumstances, considering the cost shift in terms of the $1.8 million ATRR of the Nixa Assets ensures that FERC does not take an incomplete view of the impacts of placing the Nixa Assets in Zone 10 by focusing only on how including the assets in Zone 10 impacts the non-City of Nixa customers.  Considering the full picture of the costs and benefits of the Nixa Assets to all Zone 10 customers is also consistent with SPP’s zonal rate construct, which does not evaluate the costs and benefits of transmission assets in a zone at the level of how individual customers use each of those assets, as explained above.      


[1] Sw. Power Pool, Inc., 182 FERC ¶ 61,141 (2023) (Order on Initial Decision).

[2] Sw. Power Pool, Inc., 177 FERC ¶ 63,021 (2021) (Initial Decision).

[3] GridLiance was formerly known as South Central MCN LLC.

[4] Indicated SPP Transmission Owners v. Sw. Power Pool, Inc.,                         162 FERC ¶ 61,213 (ITOs Complaint Order), reh’g denied, 165 FERC ¶ 61,005 (2018) (ITOs Complaint Rehearing Order). 

[5] Order on Initial Decision, 182 FERC ¶ 61,141 at P 4 (summarizing the basis for the Commission’s denial of the complaint in the ITOs Complaint Order and ITOs Complaint Rehearing Order).

[6] ITOs Complaint Order, 162 FERC ¶ 61,213 at P 74.

[7] GridLiance acquired the Nixa Assets from the City of Nixa on April 1, 2018.  Missouri Joint Municipal Electric Utility Commission then acquired the Nixa Assets from GridLiance on May 19, 2022.  See Sw. Power Pool, 179 FERC ¶ 61,134, at P 1, 4 (2022). 
 

[8] Sw. Power Pool, Inc., 162 FERC ¶ 61,215 (Hearing Order), order on reh’g and clarification, 164 FERC ¶ 61,120 (2018) (Rehearing Order).

[9] Initial Decision, 177 FERC ¶ 63,021 at PP 2, 188, 206.

​This summary concerns the Order Addressing Arguments Raised on Rehearing regarding reactive power compensation in MISO (Rehearing Order).
Background:  On November 30, 2022, in Docket No. ER23-523, MISO, on behalf of the MISO Transmission Owners (MISO TO),[1] submitted proposed revisions to Schedule 2, Reactive Supply and Voltage Control from Generation or Other Sources Service of OATT.  The MISO TOs proposed to eliminate all charges under Schedule 2 for the provision of reactive power within the standard power factor range for the MISO TOs’ own and affiliated generation resources.[2]  Based on the Commission’s “comparability standard,” MISO TOs stated that their proposal also terminates the obligation under Schedule 2 to pay unaffiliated generation resources in MISO for reactive power within the standard power factor range.  In its Reactive Power Order, FERC accepted the MISO TOs’ proposed Schedule 2 revisions, effective December 1, 2022.  This means that the $220 million being paid in MISO to generators for the provision of reactive power ended December 1, 2022.  

Several parties requested rehearing.  On July 12, 2023, FERC issued its Order on Rehearing (Rehearing Order - 184 FERC ¶ 61,022), modifying the discussion in the Reactive Power Order and continuing to reach the same conclusion.  Here are the items FERC discussed in its Rehearing Order: 

Comparability Standard:  FERC restated that electric power consists of two components:  real power, which is “the power that does real work—and thus the power that sellers are looking to sell and that buyers are looking to buy;” and reactive power, which is necessary to maintain adequate voltages so that real power can be transmitted.[3]  The provision of reactive power by generating facilities involves two different concepts.  Where reactive power is provided outside of the standard power factor range, it is “an ancillary service for transmitting power across the grid to serve load.”[4]  By contrast, where the generating facility is operating within the standard power factor range, “it is meeting its obligation as a generator to maintain the appropriate power factor in order to maintain voltage levels for energy entering the grid during normal operations.”[5]  Put differently, reactive support by generating facilities operating within the standard power factor range ensures that when these facilities inject real power—the product that their facilities exist to create and sell—onto the grid under normal conditions, they can do their part to maintain adequate voltages and not to threaten reliability.  FERC’s longstanding policy is  “that the provision of reactive power within the standard power factor range is, in the first instance, an obligation of the interconnecting generator and good utility practice,” such that “MISO TOs do not have an obligation to continue to compensate an independent generator for reactive power within the standard power factor range when its own or affiliated generators are no longer being compensated. 
Order No. 2003 reflects the distinction between these two different reactive power concepts.   When the transmission provider asks the interconnecting generator to operate its facility outside the established power factor range, the transmission provider is required to pay the interconnecting generator for the provision of such reactive power.   By contrast, compensation for reactive power when the generating facility is operating within the established power factor range is not required.   The sole exception FERC identified was that “if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.”   This is referred to as the comparability standard.  In the Reactive Power Order, the Commission accepted MISO TOs’ proposal to eliminate all charges under Schedule 2 for the provision of Reactive Service.  The effect of this order was not to “categorically prohibit new generation resources from seeking to recover the costs of their investment in reactive power capability.”   Rather, this order eliminated only Schedule 2’s mandated, separate stream of compensation for the capability of providing Reactive Service, which had been required in MISO consistent with the comparability standard.  This result is not unusual and is in fact already the case in other large RTOs or ISOs:  for example, Southwest Power Pool, Inc. has eliminated compensation within the power factor range,  and CAISO never provided such stand-alone compensation for Reactive Service. 
In its Rehearing Order, FERC stated that for synchronous resources, there is little or no incremental capital expenditure associated with the equipment necessary to produce reactive power because the same equipment is used to produce real power.   FERC went on to state that its conclusion that the same equipment used for Reactive Service is also necessary to produce real power is also supported by application of the AEP cost allocation methodology that apportions costs for synchronous generating plants.  As to non-synchronous resources,  the principal piece of equipment required for non-synchronous resources to produce reactive power is the inverter,  which is already necessary to convert the direct current produced by non-synchronous resources to alternating current—i.e., to supply real power that can be injected into alternating current power systems.  On rehearing and in earlier protests, no party points to any other equipment costs incurred by non-synchronous generating facilities that are attributable to providing Reactive Service.  

Reliance:  Numerous parties assert that independent power producers have come to rely on Schedule 2 compensation and argue that FERC erred in accepting MISO TOs’ proposal.  At the outset, FERC again noted that its acceptance of MISO TOs’ proposal considering the comparability standard was an application of the Commission’s long-standing policy in Order Nos. 2003 and 2003-A, consistent with its numerous subsequent decisions.  The parties on rehearing are, in effect, urging that generators’ unilateral business decisions to treat Schedule 2 compensation as irrevocable should amount to a new exception—in addition to the comparability standard—to Order No. 2003’s determination that compensation for Reactive Service should not be provided.  FERC rejected that argument in the Reactive Power Order and sustained that determination on rehearing.

Reliability:  FERC disagreed that it failed to adequately consider the effects of eliminating Schedule 2 compensation on grid reliability.   The Reactive Power Order considered the potential reliability impacts of MISO TOs’ proposal,  and FERC sustained its conclusions for the reasons articulated therein.  Moreover, arguments that accepting MISO TOs’ proposal erodes the incentive to invest in reactive power capability  are unpersuasive.  Under Order Nos. 2003 and 2003-A, reactive power capability within the standard power factor range (i.e., Reactive Service) is and remains mandatory for generator interconnection, without incentives.  The financial and other incentives for generators to invest in equipment to ensure reliability by providing reactive power outside of the standard power factor range are unaltered by and, in fact, not at issue in MISO TOs’ proposal.

Retail Rates:  Certain parties argue, primarily relying on Conway, that the possibility that generation owned or controlled by MISO TOs might recover the costs of reactive power capability from retail customers requires that independent power producers must also be compensated for such costs in their wholesale rates.   But this amounts to a generic argument that Schedule 2 compensation for Reactive Service is required not just when the transmission owner “pays its own or its affiliated generators for reactive power within the established range”  but also when the transmission owner can recover its costs through its bundled retail rates.  Neither Order Nos. 2003 and 2003-A, nor any of the Commission’s prior decisions, have ever suggested this requirement.  Arguments that Schedule 2 compensation is required unless transmission owners disclaimed the opportunity to recover Reactive Service costs in their retail rates were brought as challenges to Order No. 2003 and are not now properly before FERC.  FERC concluded that the possibility of compensation through retail rates did not give rise to a comparability issue or dictate that the Commission requires compensation under Schedule 2.   FERC further noted that Conway concerned allegations of actual anticompetitive behavior, namely that a public utility engaged in the sale of energy at both retail and wholesale sought to raise its wholesale rates in a way that would squeeze its customers, who competed with it in the retail market, out of that retail market.   The U.S. Supreme Court held that FERC has jurisdiction to consider the interplay between retail and wholesale rates in assessing a proposal to change a wholesale rate.   Here, by contrast, there are no allegations of anticompetitive behavior parallel to those in Conway, and—as noted in the Reactive Power Order—FERC  concluded that the comparability principle is satisfied by the fact that Schedule 2 compensation is being terminated for all generation, notwithstanding that the particular alternative avenues available to seek to recover Reactive Service costs may differ between transmission owners and independent power producers. 

Filing Rights and Procedures:  Some interveners argued that MISO TOs’ proposal failed to follow the appropriate procedures under Appendix K of the MISO TO Agreement in that the filing was not supported by the required majority vote nor was it the result of the required stakeholder process.  FERC found these arguments unpersuasive as there no requirement that the filing be supported by a public vote of eligible MISO TOs, under which the identity of those voting and how they voted must be disclosed, and FERC had no reason to doubt MISO TOs’ statement as to the outcome of the vote.  In the Reactive Power Order, FERC also rejected arguments that MISO TOs lacked authority to file their proposal under FPA section 205 because MISO TOs only have unilateral filing rights as to their own generators.  FERC explained it had previously found, and the D.C. Circuit in Dynegy affirmed, that pursuant to the settlement adopting section 9.6.3 of the MISO pro forma GIA, “transmission owners and the Midwest ISO share the same section 205 filing right, which is the right to submit filings under FPA section 205 to govern the rates, terms, and conditions applicable to the provision of ancillary services.”  FERC further concluded—consistent with the reasoning in the Reactive Power Order—that arguments asserting that accepting MISO TOs’ proposal undermines generators’ FPA section 205 filing rights reflect a misunderstanding of how compensation is provided for reactive service in MISO.  Specifically, whatever rights interconnection customers (including independent power producers) may have to compensation for Reactive Service must be consistent with the terms of their GIAs.   Section 9.6.3 of the MISO pro forma GIA provides that such payments shall be “pursuant to any tariff or rate schedule filed by Transmission Provider and approved by the FERC.”   Thus, generators who have GIAs with this or a similar provision have agreed to make their compensation for reactive power contingent on the contents of Schedule 2, which MISO (and MISO TOs through Appendix K) have the right to revise through an FPA section 205 filing.  Prior to FERC’s acceptance of MISO TOs’ proposal, Schedule 2 provided that the amount of such compensation for Reactive Service was determined by reference to generators’ annual reactive power revenue requirements.   MISO TOs’ proposal altered Schedule 2—and only Schedule 2—to provide that “there will be no separate charge to compensate any generation resource for reactive service within the standard power factor range.”   In other words, MISO TOs’ proposal did not adjust, overturn, or reduce to zero  any generator’s annual revenue requirement for reactive power, but rather revised the Tariff such that those revenue requirements are no longer cross-referenced as the basis for determining the amount of compensation for Reactive Service. 

Constitutional Arguments:  In the Reactive Power Order, the Commission rejected arguments that MISO TOs’ proposal violates the Takings Clause and Due Process Clause of the Fifth Amendment to the United States Constitution.   The obligation to provide Reactive Service exists independent of, and was not altered by, MISO TOs’ proposal:  it was stated in Order No. 2003 and applies to individual generators through their GIAs.   MISO TOs proposed only to change the compensation for Reactive Service, eliminating a stream of revenue under Schedule 2.  FERC thus concluded that arguments that the obligation to provide Reactive Service is unconstitutional are impermissible collateral attacks on our prior determinations. Generators do not have a property interest in continued Reactive Service compensation under the Tariff nor did MISO TOs’ proposal unconstitutionally deprive generators of that putative property interest under the Takings Clause or Due Process Clause of the Fifth Amendment.
​
Dissent:  In the Rehearing Order, Commissioner Danly reiterated his dissention.  In his dissention to the Reactive Power Order, he stated that, notwithstanding the increased rates and the administrative burden of the present compensation approach, FERC cannot simply accept the MISO TOs’ proposal unless they meet their section 205 burden that the proposed rate—in this case, the elimination of reactive power compensation—is just and reasonable based on substantial evidence in the record.  He went on to state that the MISO TOs did not offer any evidence of the effects of eliminating the $220 million annual reactive power revenue requirement from the MISO tariff, and what is clear on the record is that separate reactive power compensation has been available in MISO for several years, and parties have taken this into account in their financings, bilateral contracting, power purchase agreements, and other arrangements.


[1] MISO TOs include:  Ameren Services Company, as agent for Union Electric Company, Ameren Illinois Company, and Ameren Transmission Company of Illinois; Arkansas Electric Cooperative Corporation; City Water, Light & Power (Springfield, IL); Cooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company; and Southern Minnesota Municipal Power Agency.

[2] The phrase “standard power factor range” refers to the power factor range required for interconnection and set forth in the interconnecting generator’s generator interconnection agreement (GIA).  MISO’s pro forma GIA prescribes a power factor range of 0.95 leading to 0.95 lagging.”   

[3] Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 28 (SPP), order on reh’g,
121 FERC ¶ 61,196, at PP 16-22 (2007) (SPP Order on Rehearing); see also Bonneville, 120 FERC ¶ 61,211 at P 21 (“The purpose for which generation assets are built (including reactive power capability to maintain voltage levels for generation entering the grid) is to make sales of real power.”).

[4] Mich. Elec. Transmission Co., 97 FERC ¶ 61,187, at 61,852-53 (2001) (emphasis added).

[5] Id. at 61,853 (emphasis added); SPP, 119 FERC ¶ 61,199 at P 29; cf. Dynegy Midwest Generation, Inc., 125 FERC ¶ 61,280, at P 16 (2008) (“Reactive power is a localized service that is quickly used by transmission system components and cannot be transported over long distances.”).